Pinnacle West Capital (PNW) 10-Q 2006 Q1 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto

	Exact Name of Each Registrant as specified in
Commission	its charter; State of Incorporation; Address;	IRS Employer
File Number	and Telephone Number	Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0512431
1-4473	ARIZONA PUBLIC SERVICE COMPANY (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0011170

     Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION	Yesþ	Noo
ARIZONA PUBLIC SERVICE COMPANY	Yeso	Noþ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filerþ      Accelerated filero      Non-accelerated filero

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filero      Accelerated filero      Non-accelerated filerþ

     Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2).

PINNACLE WEST CAPITAL CORPORATION	Yeso	Noþ
ARIZONA PUBLIC SERVICE COMPANY	Yeso	Noþ

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of May 3, 2006: 99,197,295
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2006: 71,264,947

     Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) ofForm 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

     This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

TABLE OF CONTENTS

		Page
Glossary			2
Part I			4
Item 1.	Financial Statements		4
	Pinnacle West Capital Corporation		4
	Arizona Public Service Company		31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		61
Item 4.	Controls and Procedures		61
Part II			62
Item 1.	Legal Proceedings		62
Item 1A.	Risk Factors		62
Item 5.	Other Information		62
Item 6.	Exhibits		63
Signatures			65
Exhibit 12.1
Exhibit 12.2
Exhibit 12.3
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 31.4
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1
Exhibit 99.2

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

APB – Accounting Principles Board

APS – Arizona Public Service Company, a subsidiary of the Company

APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

Credit Agreement – Pinnacle West’s $300 million Amended and Restated Credit Agreement, dated as of December 9, 2005

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

El Dorado – El Dorado Investment Company, a subsidiary of the Company

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

GAAP – accounting principles generally accepted in the United States of America

IRS – United States Internal Revenue Service

kWh – kilowatt-hour

Moody’s – Moody’s Investors Service

MWh – megawatt-hours, one million watts per hour

Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company

PRP – potentially responsible party

PSA – power supply adjustor

2

PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

Retail Fuel and Power Costs – fuel and purchased power costs eligible to be deferred under the PSA

Salt River Project – Salt River Project Agricultural Improvement and Power District

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

Silverhawk – Silverhawk Power Station, a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles north of Las Vegas, Nevada

Standard & Poor’s – Standard & Poor’s Corporation

SunCor – SunCor Development Company, a subsidiary of the Company

Sundance Plant – 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

Trading – energy-related activities entered into with the objective of generating profits on changes in market prices

2005 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2005

VIE – variable interest entity

3

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)

	Three Months Ended
	March 31,
	2006			2005
OPERATING REVENUES
Regulated electricity segment	$	466,126		$	416,030
Marketing and trading segment		85,002			89,257
Real estate segment		107,854			69,936
Other revenues		11,224			10,135
Total		670,206			585,358
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		157,395			78,423
Marketing and trading segment fuel and purchased power		74,175			70,809
Operations and maintenance		178,427			155,084
Real estate segment operations		71,330			55,334
Depreciation and amortization		87,621			90,944
Taxes other than income taxes		35,573			34,565
Other expenses		8,522			8,374
Total		613,043			493,533
OPERATING INCOME		57,163			91,825
OTHER
Allowance for equity funds used during construction		3,801			2,603
Other income (Note 14)		5,467			1,726
Other expense (Note 14)		(4,541	)		(5,309	)
Total		4,727			(980	)
INTEREST EXPENSE
Interest charges		47,526			45,965
Capitalized interest		(4,024	)		(3,289	)
Total		43,502			42,676
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		18,388			48,169
INCOME TAXES		6,793			18,570
INCOME FROM CONTINUING OPERATIONS		11,595			29,599
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $557 and $(3,320) (Note 17)		860			(5,151	)
NET INCOME	$	12,455		$	24,448
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		99,115			91,962
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		99,449			92,045
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	0.12		$	0.32
Net income – basic		0.13			0.27
Income from continuing operations – diluted		0.12			0.32
Net income – diluted		0.13			0.27
DIVIDENDS DECLARED PER SHARE	$	1.00		$	0.95

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

4

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	314,855		$	154,003
Customer and other receivables		379,730			502,681
Allowance for doubtful accounts		(4,596	)		(4,979	)
Materials and supplies (at average cost)		112,350			109,736
Fossil fuel (at average cost)		22,145			23,658
Assets from risk management and trading activities (Note 10)		501,871			827,779
Assets held for sale (Note 17)		—			202,645
Other current assets		83,406			75,869
Total current assets		1,409,761			1,891,392
INVESTMENTS AND OTHER ASSETS
Real estate investments – net		427,297			390,702
Assets from long-term risk management and trading activities (Note 10)		385,100			597,831
Decommissioning trust accounts		305,096			293,943
Other assets		119,264			111,931
Total investments and other assets		1,236,757			1,394,407
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		10,838,110			10,727,695
Less accumulated depreciation and amortization		3,672,003			3,622,884
Total		7,166,107			7,104,811
Construction work in progress		307,950			327,172
Intangible assets, net of accumulated amortization		109,435			90,916
Nuclear fuel, net of accumulated amortization		61,806			54,184
Net property, plant and equipment		7,645,298			7,577,083
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		169,486			172,756
Other regulatory assets		167,155			151,123
Other deferred debits		127,671			135,884
Total deferred debits		464,312			459,763
TOTAL ASSETS	$	10,756,128		$	11,322,645

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

5

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2006			2005
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	259,149		$	377,107
Accrued taxes		326,948			289,235
Accrued interest		48,828			31,774
Dividends payable		49,588			—
Short-term borrowings		10,603			15,673
Current maturities of long-term debt		384,055			384,947
Customer deposits		64,242			60,509
Deferred income taxes		32,160			94,710
Liabilities from risk management and trading activities (Note 10)		490,460			720,693
Other current liabilities (Note 10)		130,888			297,425
Total current liabilities		1,796,921			2,272,073
LONG-TERM DEBT LESS CURRENT MATURITIES		2,782,227			2,608,455
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,202,226			1,225,253
Regulatory liabilities		571,939			592,494
Liability for asset retirements		273,238			269,011
Pension liability		285,735			264,476
Liabilities from long-term risk management and trading activities (Note 10)		230,629			256,413
Unamortized gain – sale of utility plant		44,613			45,757
Other		357,869			363,749
Total deferred credits and other		2,966,249			3,017,153
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13 and 15)
COMMON STOCK EQUITY
Common stock, no par value		2,075,157			2,067,377
Treasury stock		(895	)		(1,245	)
Total common stock		2,074,262			2,066,132
Accumulated other comprehensive income (loss) (Note 11):
Minimum pension liability adjustment		(97,277	)		(97,277	)
Derivative instruments		126,775			262,397
Total accumulated other comprehensive income		29,498			165,120
Retained earnings		1,106,971			1,193,712
Total common stock equity		3,210,731			3,424,964
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	10,756,128		$	11,322,645

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

6

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2006			2005 (a)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	12,455		$	24,448
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		95,072			99,556
Deferred fuel and purchased power		(14,538	)		—
Deferred fuel amortization		17,808			—
Allowance for equity funds used during construction		(3,801	)		(2,603	)
Deferred income taxes		1,757			(4,281	)
Change in mark-to-market valuations		9,305			(18,557	)
Changes in current assets and liabilities:
Customer and other receivables		129,940			117,132
Materials, supplies and fossil fuel		4,186			(9,967	)
Other current assets		(7,537	)		(10,265	)
Accounts payable		(124,577	)		(179,467	)
Accrued taxes		37,713			31,768
Other current liabilities		24,940			22,113
Proceeds from the sale of real estate assets		7,884			19,427
Real estate investments		(28,670	)		(13,797	)
Change in risk management and trading – assets		67,984			(1,198	)
Change in risk management and trading – liabilities		(66,096	)		37,707
Collateral		(170,690	)		32,946
Change in other long-term assets		(2,247	)		(1,676	)
Change in other long-term liabilities		12,169			19,064
Net cash flow provided by operating activities		3,057			162,350
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(167,367	)		(121,120	)
Proceeds from the sale of Silverhawk		207,620			—
Capitalized interest		(4,024	)		(3,289	)
Purchases of investment securities		(269,526	)		(343,525	)
Proceeds from sale of investment securities		269,526			424,700
Proceeds from nuclear decommissioning trust sales		33,743			39,777
Investment in nuclear decommissioning trust		(38,929	)		(42,638	)
Proceeds from real estate investments		2,138			1,869
Other		(1,484	)		8,999
Net cash flow provided by (used for) investing activities		31,697			(35,227	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		206,848			163,999
Short-term borrowings and payments – net		(70	)		(7,778	)
Dividends paid on common stock		(49,608	)		(43,666	)
Repayment of long-term debt		(39,587	)		(264,805	)
Common stock equity issuance		5,065			12,649
Other		3,450			21,228
Net cash flow provided by (used for) financing activities		126,098			(118,373	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		160,852			8,750
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		154,003			163,366
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	314,855		$	172,116
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	(40	)	$	15,230
Interest paid, net of amounts capitalized	$	25,526		$	33,891

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

(a) See Note 1 for information regarding revisions of prior year amounts.

7

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

     The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our wholly-owned subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado. All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

     In the second quarter of 2005, Pinnacle West revised the presentation of its statements of cash flows to include the cash flows from discontinued operations within the categories of operating, investing, and financing activities. A summary of the effects of the change in presentation on the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2005 is as follows (dollars in millions):

	Three Months Ended
	March 31, 2005
Net cash flows from operating activities as previously reported	$	196
Change in net cash flows from discontinued operations		(34	)
Net cash flows from operating activities as currently reported	$	162
Net cash flows used for investing activities as previously reported	$	(40	)
Change in net cash flows used for discontinued operations		5
Net cash flows used for investing activities as currently reported	$	(35	)
Net cash flows used for financing activities as previously reported	$	(147	)
Change in net cash flows used for discontinued operations		29
Net cash flows used for financing activities as currently reported	$	(118	)

2. Condensed Consolidated Financial Statements

     Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2005 Form 10-K.

3. Quarterly Fluctuations

     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate and trading and wholesale marketing activities can have significant impacts on our results for

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

interim periods. For these reasons, results for interim periods do not necessarily represent results to be expected for the year.

4. Changes in Liquidity

      In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).

     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of March 31, 2006:

Year	Pinnacle West		APS
2006	$	386	$	85
2007		2		1
2008		112		1
2009		10		1
2010		228		224
Thereafter		2,439		2,262

5. Regulatory Matters

APS General Rate Case

     On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other data in the general rate case that APS originally filed on November 4, 2005. As requested by the ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test period instead of the test year ended December 31, 2004 used in APS’ original filing. As a result of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006. The original filing requested a 19.9%, or $409.1 million, retail rate increase.

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The updated requested rate increase is designed to recover the following (dollars in millions):

	Updated Filing						Original Filing
	(January 31, 2006)						(November 4, 2005)
	Annual						Annual
	Revenue			Percentage			Revenue			Percentage
	Increase			Increase			Increase			Increase
Increased fuel and purchased power	$	299.0			14.0	%	$	246.8			12.0	%
Capital structure update		98.3			4.6	%		96.8			4.7	%
Rate base update, including acquisition of Sundance Plant		46.2			2.2	%		42.5			2.1	%
Pension funding		41.3			1.9	%		41.2			2.0	%
Other items		(30.9	)		(1.4	)%		(18.2	)		(0.9	)%
Total increase	$	453.9			21.3	%	$	409.1			19.9	%

     The request is based on (a) a rate base of $4.4 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.031904 per kilowatt-hour based on estimated 2006 prices; and (c) a proposed capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). The requested increase in annual retail electricity revenues from the original filing is based solely on increased fuel and purchased power costs, slightly offset by other items (see the above chart). If the ACC approves the requested base rate increase for fuel and purchased power costs (see clause (b) of this paragraph), subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates.

     The updated request does not include the PSA annual adjustor rate increase of approximately 5% that took effect February 1, 2006 or the pending application for a PSA surcharge that APS filed on February 2, 2006. See “Power Supply Adjustor” below.

Interim Rate Increase

     On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase is solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

• authorizes an interim PSA adjustor, effective May 1, 2006, that will result in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs during 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Application for PSA Surcharges” below), will result in a rate increase of

10

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);
•	provides that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (PSA deferrals related to these outages are estimated to be about $32 million during the quarter ended March 31, 2006);
•	encourages parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;
•	affirms APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and
•	encourages APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”

The interim PSA adjustor accelerates recovery of the fuel and purchased power component of APS’ general rate case and is not an additional increase.

Power Supply Adjustor

     PSA Provisions

     The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:

• APS will record deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);

• the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the base fuel amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;

• amounts to be recovered or refunded through the PSA adjustor are limited to a)  a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;

11

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;

• the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and

• APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end, which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.

     2006 PSA Annual AdjustorThe effective date of the PSA’s annual adjustor is February 1, and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective February 1, 2006. The change in the adjustor rate represents a retail rate increase of approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over the twelve-month period beginning February 1, 2006, of which $18 million was recorded as revenue and fuel and purchased power costs during the quarter ended March 31, 2006.

     Application for PSA SurchargesOn February 2, 2006, APS filed with the ACC an application for two separate surcharges under the PSA. The surcharges would recover approximately $60 million in retail fuel and purchased power costs deferred by APS in 2005 under the PSA. The combined surcharges would represent a temporary rate increase of approximately 2.6% during the overlapping portion of the twelve-month recovery periods for the two surcharges. The other component of the 2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor discussed in the preceding paragraph. The first surcharge would recover approximately $15 million over a twelve-month period, representing a temporary rate increase of approximately 0.7%, proposed to begin with the date of the ACC’s decision in APS’ emergency interim rate case. The second requested surcharge would recover approximately $45 million over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. The $45 million of PSA deferrals represents replacement power costs associated with these outages. On April 12, 2006, the ACC issued an order approving the $15 million surcharge request. As a result of the ACC’s decision described under “Interim Rate Increase” above, this temporary rate increase became effective May 1, 2006. The second surcharge request is still pending.

     Proposed Modifications to PSA (Requested In General Rate Case)

     In its pending general rate case, APS has requested the following modifications to the PSA:

• The cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 limit to changes in the adjustor rate in any one year would remain in effect;

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PINNACLE WEST CAPITAL CORPORATION
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• The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);

• The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made;

• The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power costs above the base fuel amount and retains 10% of the benefit from retail fuel and purchased power costs that are below the base fuel amount; and

• 10% of any realized gains or losses resulting from APS’ hedges of Retail Fuel and Power Costs would be retained or absorbed by APS before being subject to the 90/10 sharing provision under the PSA.

APS 2003 Rate Case

     On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. In addition to the ACC’s approval of the PSA discussed under “Power Supply Adjustor” above, certain key financial components of the order include:

• APS received an annual retail rate increase of approximately 4.2%, which was effective as of April 1, 2005. This increase does not include the impact of the PSA.

• APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in the third quarter of 2005.

• Effective April 1, 2005, APS adopted longer service lives for certain depreciable assets. This change reduced annual depreciation expense for financial reporting purposes by approximately $30 million. APS also adopted longer service lives for the PWEC Dedicated Assets, which reduced annual depreciation expense for financial reporting purposes by approximately $10 million.

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Equity Infusions

     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consist of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006 (see Note 17). Pinnacle West has made these equity infusions into APS.

Federal

     Price Mitigation Plan

     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

     FERC Order

     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to its three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ market-based rate authority in the APS control area (the “FERC Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the APS control area to allow the FERC to make a determination about the FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

     As a result of the FERC Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area, with an effective date of February 27, 2005. The Pinnacle West Companies will be required to refund any over-collection of rates from February 27, 2005.

 ��   The Pinnacle West Companies will seek rehearing of the FERC Order on or before May 17, 2006. Based upon an analysis of the FERC Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the FERC Order has a material adverse effect on its financial position, results of operations or cash flows.

     In addition, the FERC Order revoked a previously-granted FERC order allowing Pinnacle West to issue securities or incur long-term debt without FERC approval. On May 3, 2006, the FERC issued an order approving Pinnacle West’s April 20, 2006 application to borrow funds under the Credit Agreement and to issue a broad range of other debt and equity securities.

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6. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

     The following table provides details of the plans’ benefit costs for the three months ended March 31, 2006 and 2005. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):

	Pension Benefits						Other Benefits
	Three Months						Three Months
	Ended						Ended
	March 31,						March 31,
	2006			2005			2006			2005
Service cost-benefits earned during the period	$	15		$	12		$	7		$	6
Interest cost on benefit obligation		29			23			13			9
Expected return on plan assets		(30	)		(24	)		(13	)		(8	)
Amortization of:
Transition (asset) obligation		—			(1	)		1			1
Prior service cost		1			1			—			—
Net actuarial loss		7			5			3			2
Net periodic benefit cost	$	22		$	16		$	11		$	10
Portion of cost charged to expense	$	9		$	7		$	5		$	4
APS’ share of costs charged to expense	$	8		$	6		$	4		$	4

Contributions

     The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $14 million of which was contributed on April 14, 2006. The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS’ share is approximately 97% of both plans.

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7. Business Segments

     We have three principal business segments (determined by products, services and the regulatory environment):

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution;

• our real estate segment, which consists of SunCor’s real estate development and investment activities; and

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

     Financial data for the three months ended March 31, 2006 and 2005 and at March 31, 2006 and December 31, 2005 by business segment is provided as follows (dollars in millions):

	Three Months Ended
	March 31,
	2006			2005
Operating Revenues:
Regulated electricity	$	466		$	416
Real estate		108			70
Marketing and trading		85			89
Other		11			10
Total	$	670		$	585
Net Income (Loss):
Regulated electricity	$	(12	)	$	14
Real estate		21			9
Marketing and trading		2			—
Other		1			1
Total	$	12		$	24

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	As of		As of
	March 31, 2006		December 31, 2005
Assets:
Regulated electricity	$	9,756	$	9,732
Real estate		517		483
Marketing and trading		452		1,070
Other		31		38
Total	$	10,756	$	11,323

8. Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and our subsidiaries.

     The 2002 Long-Term Incentive Plan (“2002 Plan”) allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. We have reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.

     Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year period based upon PinnacleWest’s earnings per share growth rate during that three-year period compared to the earnings per share growth rate of all relevant companies in a specified utilities index. The number of shares of common stock a recipient is entitled to receive is determined by Pinnacle West’s relative percentile ranking during the three-year period.

     The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new options may be granted under the plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

     In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25, “Accounting for Stock Issued to Employees.”

     Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application transition method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based

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compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.

     The compensation cost that has been charged against income for share-based compensation plans was $2.9 million and $0.6 million for the quarters ended March 31, 2006 and 2005, respectively. The total income tax benefit recognized in the condensed consolidated income statement for share-based compensation arrangements was $1.1 million and $0.2 million for the quarters ended March 31, 2006 and 2005, respectively.

     The following table is a summary of option activity under our equity incentive plans as of March 31, 2006 and changes during the quarter ending on that date:

						Weighted-
						Average		Aggregate
				Weighted-		Remaining		Intrinsic Value
		Shares		Average Exercise		Contractual Term		(dollars in
Options	(in thousands)				Price		(Years)		thousands)
Outstanding at January 1, 2006		1,696		$	39.65
Granted		—			—
Exercised		(2	)		32.29
Forfeited or expired		(6	)		43.29
Outstanding at March 31, 2006		1,688			39.64		4.9	$	2,930
Exercisable at March 31, 2006		1,682			39.65		4.9		2,923

     There were no options granted during the quarters ended March 31, 2006 and 2005. The intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005 was not material.

     The following table is a summary of the status of stock compensation awards, other than options, as of March 31, 2006 and changes during the quarter ending on that date:

	Shares			Weighted-Average Grant-Date
Nonvested shares	(in thousands)			Fair Value
Nonvested at January 1, 2006		528		$	38.23
Granted		274			41.50
Vested		(13	)		44.13
Forfeited		(217	)		35.96
Nonvested at March 31, 2006		572			40.52

     As of March 31, 2006, there was $10.4 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested during the quarters ended March 31, 2006 and 2005 was $0.5 million and $2.9 million, respectively.

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     Cash received from options exercised under our share-based payment arrangements for the quarter ended March 31, 2006 was $0.1 million and for the quarter ended March 31, 2005 was $4.0 million. The actual tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was immaterial for the three months ended March 31, 2006 or 2005.

     Pinnacle West has a current policy of issuing new shares to satisfy share requirements for stock compensation plans and does not expect to repurchase any shares during 2006.

9. Variable-Interest Entities

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2006, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.

10. Derivative and Energy Trading Accounting

     We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits, as well as interest rate risk associated with long-term debt. As of March 31, 2006, we hedged exposures to the price variability of the power and gas commodities for a maximum of 3.25 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2006 and 2005 are comprised of the following (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended
	March 31,
	2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(178	)	$	7,324
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		(18	)		858
Gains from the discontinuance of cash flow hedges		434			385

     During the next twelve months ending March 31, 2007, we estimate that a net gain of $73 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments.

     The following table summarizes our assets and liabilities from risk management and trading activities at March 31, 2006 and December 31, 2005 (dollars in thousands):

March 31, 2006

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	381,639	$	194,319	$	(350,517	)	$	(121,356	)	$	104,085
Margin account and options		45		—		(58,224	)		—			(58,179	)
Marketing and trading:
Mark-to-market		118,925		178,740		(58,668	)		(108,466	)		130,531
Options and emission allowances – at cost		1,262		12,041		(23,051	)		(807	)		(10,555	)
Total	$	501,871	$	385,100	$	(490,460	)	$	(230,629	)	$	165,882

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing and trading:
Mark-to-market		307,883		291,122		(236,922	)		(181,417	)		180,666
Options and emission allowances – at cost		1,683		77,836		(23,805	)		(209	)		55,505
Total	$	827,779	$	597,831	$	(720,693	)	$	(256,413	)	$	448,504

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million at December 31, 2005 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $10 million at March 31, 2006 and $6 million at December 31, 2005, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $46 million at March 31, 2006 and $216 million at December 31, 2005, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

Fair Value Hedges

     On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% Senior Notes. The purpose of these hedges was to protect against significant fluctuations in the fair value of our debt. These interest rate swaps were considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of our debt. The fair value of the interest rate swaps was a loss of approximately $1.7 million at March 31, 2006 and is included in other current liabilities with the corresponding offset in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. These interest rate swaps were settled in April 2006.

Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 10% of Pinnacle West’s $887

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million of risk management and trading assets as of March 31, 2006. Our risk management process assesses and monitors the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, including the counterparty discussed above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

11. Comprehensive Income (Loss)

     Components of comprehensive income (loss) for the three months ended March 31, 2006 and 2005 are as follows (dollars in thousands):

	Three Months Ended
	March 31,
	2006			2005
Net income	$	12,455		$	24,448
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(204,983	)		159,644
Net reclassification of realized gains to income (b)		(17,530	)		(5,919	)
Net income tax benefit (expense) related to items of other comprehensive income (loss)		86,891			(60,306	)
Total other comprehensive income (loss)		(135,622	)		93,419
Comprehensive income (loss)	$	(123,167	)	$	117,867

(a)	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
(b)	These amounts primarily include the reclassification of unrealized gains and losses to realized for contracted commodities delivered during the period.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

     Spent Nuclear Fuel and Waste Disposal

     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims.

     APS currently estimates it will incur $147 million (in 2005 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2006, APS had a regulatory asset of $4 million that represents amounts spent for on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was effective April 1, 2005.

California Energy Market Issues and Refunds in the Pacific Northwest

     FERC

     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under

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PINNACLE WEST CAPITAL CORPORATION
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market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted upon, and the outcome of the further proceedings cannot be predicted at this time.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.

     On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

FERC Order

     See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.

Natural Gas Supply

     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.

     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the costs responsibility associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9, 2003 order.

24

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million after income taxes for the period September 2003 through December 2005. This appeal has been stayed pending further consideration by the FERC.

     Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposed new rates and new services to become effective on January 1, 2006. The FERC allowed the new rates to take effect on January 1, 2006, but made the rates subject to refund pending the outcome of a hearing. On March 23, 2006, the FERC issued an order approving El Paso’s proposed new services. APS has sought rehearing of this order. On March 29, 2006, El Paso filed a partial settlement that postpones the implementation and the associated cost impact of the new services until June 1, 2006. As part of this settlement, El Paso will accept bids for new services that will be evaluated and awarded on a net present value, first-come, first-serve basis. APS will be able to evaluate the cost impact of these new services once it has been notified of the services contracts it has been awarded. APS cannot currently predict the outcome of this matter; however, APS believes most of these increased costs would be eligible for recovery under the PSA (see Note 5).

Navajo Nation Litigation

     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.

Superfund

     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because

25

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.

Litigation

     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations, cash flows or liquidity.

13. Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.

     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $17.8 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Other Income and Other Expense

     The following table provides detail of other income and other expense for the three months ended March 31, 2006 and 2005 (dollars in thousands):

26

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended
	March 31,
	2006			2005
Other income:
Interest income	$	4,905		$	1,320
Asset sales		361			241
SunCor (a)		166			(28	)
Miscellaneous		35			193
Total other income	$	5,467		$	1,726
Other expense:
Non-operating costs (b)	$	(3,719	)	$	(3,098	)
Asset sales		(196	)		(64	)
Investment losses – net		(31	)		(1,249	)
Miscellaneous		(595	)		(898	)
Total other expense	$	(4,541	)	$	(5,309	)

(a)	Includes joint venture and other non-operating income.
(b)	As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

15. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of one of our unregulated subsidiaries. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our unregulated subsidiary would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of its subsidiary. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. At March 31, 2006, we had a guarantee of $18 million with a term of one year and a surety bond of $65 million with a term of one year for APS Energy Services.

     At March 31, 2006, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2006. These letters of credit were subsequently extended and expire in 2007. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2006, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $93 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring

27

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

in 2006. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

16. Earnings Per Share

     The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2006 and 2005:

	Three Months Ended
	March 31,
	2006		2005
Basic earnings per share:
Income from continuing operations	$	0.12	$	0.32
Income (loss) from discontinued operations		0.01		(0.05	)
Earnings per share – basic	$	0.13	$	0.27
Diluted earnings per share:
Income from continuing operations	$	0.12	$	0.32
Income (loss) from discontinued operations		0.01		(0.05	)
Earnings per share – diluted	$	0.13	$	0.27

     Dilutive stock options and performance shares increased average common shares outstanding by approximately 334,000 shares and 83,000 shares for the three months ended March 31, 2006 and March 31, 2005, respectively.

     Options to purchase 747,874 shares for the three-month period ended March 31, 2006 were outstanding but were not included in the computation of earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share for that same reason were 868,934 shares for the three-month period ended March 31, 2005.

17. Discontinued Operations

     Silverhawk(marketing and trading segment)–In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on

28

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

January 10, 2006. The marketing and trading segment discontinued operations amounts in the chart below are the revenues and expenses related to the operations of Silverhawk.

     SunCor(real estate segment)–In 2005 and 2006, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144.

     The following table provides revenue and income (loss) before income taxes and after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2006 and 2005 (dollars in millions):

	Three Months Ended
	March 31,
	2006		2005
Revenue:
Silverhawk	$	1	$	28
SunCor – commercial operations		1		4
Total revenue	$	2	$	32
Income (loss) before taxes:
Silverhawk (a)	$	—	$	(10	)
SunCor – commercial operations		1		2
Total income (loss) before taxes	$	1	$	(8	)
Income (loss) after taxes:
Silverhawk	$	—	$	(7	)
SunCor – commercial operations		—		1
Total income (loss) after taxes	$	—	$	(6	)

(a) For the three months ended March 31, 2005, income (loss) before income taxes includes an interest expense allocation, net of capitalized costs, of $3 million. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.

18. Nuclear Decommissioning Trust

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in debt and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2006 and December 31, 2005 (dollars in millions):

29

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
March 31, 2006
Equity securities	$	160	$	56	$	—
Debt securities		145		1		2
Total	$	305	$	57	$	2
December 31, 2005
Equity securities	$	150	$	50	$	—
Debt securities		144		3		1
Total	$	294	$	53	$	1

     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Three Months Ended March 31,
	2006			2005
Realized gains	$	1		$	1
Realized losses		(1	)		(1	)
Proceeds from the sale of securities		34			40

     The fair value of debt securities, summarized by contractual maturities, at March 31, 2006 is as follows:

	March 31,
Fair Value (in millions)	2006
Less than one year	$	10
1 year - 5 years		36
5 years - 10 years		38
Greater than 10 years		61
Total	$	145

30

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2006			2005
ELECTRIC OPERATING REVENUES
Regulated electricity	$	467,222		$	418,434
Marketing and trading		9,647			22,858
Total		476,869			441,292
OPERATING EXPENSES
Regulated electricity fuel and purchased power		158,274			81,914
Marketing and trading fuel and purchased power		1,368			28,302
Operations and maintenance		173,353			142,294
Depreciation and amortization		86,311			82,214
Income taxes		(3,029	)		16,380
Other taxes		35,548			31,445
Total		451,825			382,549
OPERATING INCOME		25,044			58,743
OTHER INCOME (DEDUCTIONS)
Income taxes		236			(837	)
Allowance for equity funds used during construction		3,801			2,603
Other income (Note S-3)		4,806			6,161
Other expense (Note S-3)		(3,680	)		(3,860	)
Total		5,163			4,067
INTEREST DEDUCTIONS
Interest on long-term debt		34,250			35,517
Interest on short-term borrowings		2,026			1,191
Debt discount, premium and expense		1,173			1,004
Allowance for borrowed funds used during construction		(1,721	)		(1,947	)
Total		35,728			35,765
NET INCOME (LOSS)	$	(5,521	)	$	27,045

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

31

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2006			2005
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	10,793,563		$	10,682,999
Less accumulated depreciation and amortization		3,665,740			3,616,886
Total		7,127,823			7,066,113
Construction work in progress		292,893			314,584
Intangible assets, net of accumulated amortization		108,922			90,327
Nuclear fuel, net of accumulated amortization		61,806			54,184
Utility plant – net		7,591,444			7,525,208
INVESTMENTS AND OTHER ASSETS
Decommissioning trust accounts		305,096			293,943
Assets from long-term risk management and trading activities (Note S-1)		198,329			234,372
Other assets		65,612			64,128
Total investments and other assets		569,037			592,443
CURRENT ASSETS
Cash and cash equivalents		76,645			49,933
Customer and other receivables		304,569			421,621
Allowance for doubtful accounts		(3,192	)		(3,568	)
Materials and supplies (at average cost)		112,350			109,736
Fossil fuel (at average cost)		22,145			23,658
Assets from risk management and trading activities (Note S-1)		387,426			532,923
Other current assets		10,229			14,639
Total current assets		910,172			1,148,942
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		169,486			172,756
Other regulatory assets		167,155			151,123
Unamortized debt issue costs		24,630			25,279
Other deferred debits		87,291			91,690
Total deferred debits		448,562			440,848
TOTAL ASSETS	$	9,519,215		$	9,707,441

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

32

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	March 31,			December 31,
	2006			2005
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital (Note 5)		2,063,098			1,853,098
Retained earnings		770,154			860,675
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(86,132	)		(86,132	)
Derivative instruments		73,974			179,422
Common stock equity		2,999,256			2,985,225
Long-term debt less current maturities		2,479,689			2,479,703
Total capitalization		5,478,945			5,464,928
CURRENT LIABILITIES
Current maturities of long-term debt		85,018			85,620
Accounts payable		149,529			215,384
Accrued taxes		391,080			360,737
Accrued interest		35,262			25,003
Dividends payable		42,500			—
Customer deposits		57,192			55,474
Deferred income taxes		8,682			64,210
Liabilities from risk management and trading activities (Note S-1)		413,299			480,138
Other current liabilities (Note S-1)		97,012			227,398
Total current liabilities		1,279,574			1,513,964
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,205,489			1,215,403
Regulatory liabilities		571,939			592,494
Liability for asset retirements		273,238			269,011
Pension liability		253,298			233,342
Customer advances for construction		62,248			60,287
Unamortized gain – sale of utility plant		44,613			45,757
Liabilities from long-term risk management and trading activities (Note S-1)		129,029			83,774
Other		220,842			228,481
Total deferred credits and other		2,760,696			2,728,549
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13, 15 and S-4)
TOTAL CAPITALIZATION AND LIABILITIES	$	9,519,215		$	9,707,441

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

33

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Three Months Ended
	March 31,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(5,521	)	$	27,045
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		93,762			87,539
Deferred fuel and purchased power		(14,538	)		—
Deferred fuel amortization		17,808			—
Allowance for equity funds used during construction		(3,801	)		(2,603	)
Deferred income taxes		1,757			(1,009	)
Change in mark-to-market valuations		974			(8,234	)
Changes in current assets and liabilities:
Customer and other receivables		124,568			70,493
Materials, supplies and fossil fuel		(1,101	)		(5,309	)
Other current assets		4,892			3,089
Accounts payable		(62,543	)		(123,460	)
Accrued taxes		30,343			47,839
Collateral		(150,640	)		31,080
Other current liabilities		32,231			(29,573	)
Change in risk management and trading activities – liabilities		(65,131	)		36,204
Change in other long-term assets		(5,335	)		(11,821	)
Change in other long-term liabilities		11,366			6,168
Net cash flow provided by operating activities		9,091			127,448
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(140,185	)		(117,501	)
Allowance for borrowed funds used during construction		(1,721	)		(1,947	)
Purchases of investment securities		(122,025	)		(67,450	)
Proceeds from sale of investment securities		122,025			248,625
Proceeds from nuclear decommissioning trust sales		33,743			39,777
Investment in nuclear decommissioning trust		(38,929	)		(42,638	)
Other		(1,966	)		8,934
Net cash flow provided by (used for) investing activities		(149,058	)		67,800
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			163,975
Equity infusion		210,000			—
Dividends paid on common stock		(42,500	)		(42,500	)
Repayment and reacquisition of long-term debt		(821	)		(264,482	)
Net cash flow provided by (used for) financing activities		166,679			(143,007	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		26,712			52,241
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		49,933			49,575
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	76,645		$	101,816
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes paid, net of refunds	$	—		$	9
Interest, net of amounts capitalized	$	24,297		$	30,149

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

34

     Certain notes to APS’ Condensed Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’ Condensed Financial Statements. In addition, listed below are the Supplemental Notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.

	Condensed	APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Consolidation and Nature of Operations	Note 1	—
Condensed Consolidated Financial Statements	Note 2	—
Quarterly Fluctuations	Note 3	—
Changes in Liquidity	Note 4	—
Regulatory Matters	Note 5	—
Retirement Plans and Other Benefits	Note 6	—
Business Segments	Note 7	—
Stock-Based Compensation	Note 8	—
Variable Interest Entities	Note 9	—
Derivative and Energy Trading Accounting	Note 10	Note S-1
Comprehensive Income	Note 11	Note S-2
Commitments and Contingencies	Note 12	—
Nuclear Insurance	Note 13	—
Other Income and Other Expense	Note 14	Note S-3
Guarantees	Note 15	—
Earnings Per Share	Note 16	—
Discontinued Operations	Note 17	—
Nuclear Decommissioning Trust	Note 18	—
Related Party Transactions	—	Note S-4

35

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-1. Derivative and Energy Trading Accounting

     APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels, and emission allowances and credits. As of March 31, 2006, APS hedged exposures to these risks for a maximum of 3.25 years.

Cash Flow Hedges

     The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2006 and 2005 were comprised of the following (dollars in thousands):

	Three Months Ended
	March 31,
	2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(436	)	$	7,417
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		(18	)		858
Gains from the discontinuance of cash flow hedges		159			302

     During the next twelve months ending March 31, 2007, APS estimates that a net gain of $41 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     APS’ assets and liabilities from risk management and trading activities are presented in two categories, consistent with Pinnacle West’s business segments.

     The following table summarizes APS’ assets and liabilities from risk management and trading activities at March 31, 2006 and December 31, 2005 (dollars in thousands):

36

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

March 31, 2006

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	381,639	$	194,319	$	(350,517	)	$	(121,356	)	$	104,085
Margin account and options		45		—		(58,224	)		—			(58,179	)
Marketing and Trading:
Mark-to-market		4,480		4,010		(4,347	)		(6,866	)		(2,723	)
Options at cost		1,262		—		(211	)		(807	)		244
Total	$	387,426	$	198,329	$	(413,299	)	$	(129,029	)	$	43,427

December 31, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing and Trading:
Mark-to-market		13,027		5,499		(20,172	)		(8,778	)		(10,424	)
Options at cost		1,683		—		—			(209	)		1,474
Total	$	532,923	$	234,372	$	(480,138	)	$	(83,774	)	$	203,383

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $57 million at March 31, 2006 and $123 million at December 31, 2005 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at March 31, 2006 or December 31, 2005. Collateral provided to us by counterparties was $24 million at March 31, 2006 and $175 million at December 31, 2005, and is included in other current liabilities on the Condensed Balance Sheets.

S-2. Comprehensive Income (Loss)

     Components of APS’ comprehensive income (loss) for the three months ended March 31, 2006 and 2005 are as follows (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

	Three Months Ended
	March 31,
	2006			2005
Net income (loss)	$	(5,521	)	$	27,045
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		(162,892	)		108,217
Net reclassification of realized gains to income (b)		(10,116	)		(1,381	)
Net income tax benefit (expense) related to items of other comprehensive income (loss)		67,560			(42,061	)
Total other comprehensive income (loss)		(105,448	)		64,775
Comprehensive income (loss)	$	(110,969	)	$	91,820

(a)	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.
(b)	These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.

S-3. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for the three months ended March 31, 2006 and 2005 (dollars in thousands):

	Three Months Ended
	March 31,
	2006			2005
Other income:
Interest income	$	3,534		$	5,423
Asset sales		361			241
Investment gains – net		875			—
Miscellaneous		36			497
Total other income	$	4,806		$	6,161
Other expense:
Non-operating costs (a)	$	(3,216	)	$	(2,628	)
Asset sales		(196	)		(64	)
Investment losses – net		—			(502	)
Miscellaneous		(268	)		(666	)
Total other expense	$	(3,680	)	$	(3,860	)

(a) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-4. Related Party Transactions

     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars in millions):

	Three Months Ended
	March 31,
	2006		2005
Electric operating revenues:
Pinnacle West – marketing and trading	$	1	$	1
Pinnacle West Energy		—		1
Total	$	1	$	2
Fuel and purchased power costs:
Pinnacle West Energy	$	—	$	8
Other:
Pinnacle West Energy interest income	$	—	$	5

	As of			As of
	March 31, 2006			December 31, 2005
Net intercompany receivables (payables):
Pinnacle West – marketing and trading	$	27		$	82
APS Energy Services		1			2
Pinnacle West		(17	)		(2	)
Total	$	11		$	82

     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. APS purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”

     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

     The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial Statements and the related Notes that appear in Item 1 of this report.

OVERVIEW

     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

     The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, APS has pending before the ACC:

• a general retail rate case pursuant to which APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006; and

• an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages, which were deferred by APS in 2005 under the PSA.

     See “Deferred Fuel and Purchased Power Costs” below for a discussion of Palo Verde Unit 1’s current outage to remedy an operating condition, the unit’s previous reduced power levels resulting from that condition, and the associated economic impact.

     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.

     Pinnacle West Energy is our subsidiary that previously owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case” in Note 5. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. See Note 17 for discussion of discontinued operations. As a result, Pinnacle West Energy no longer owns any generating plants and has ceased operations.

     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction.

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We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     Pinnacle West has three principal business segments (determined by products, services and the regulatory environment):

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution;

• our real estate segment, which consists of SunCor’s real estate development and investment activities; and

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

     The following table summarizes net income for the three months ended March 31, 2006 and 2005 (dollars in millions):

	Three Months Ended
	March 31,
	2006			2005
Regulated electricity	$	(12	)	$	14
Real estate		21			8
Marketing and trading		2			7
Other		1			1
Income from continuing operations		12			30
Discontinued operations – net of tax:
Real estate (a)		—			1
Marketing and trading (b)		—			(7	)
Net income	$	12		$	24

(a)	Primarily relates to sales of commercial properties.
(b)	Primarily relates to the operations of Silverhawk.

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PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.1 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.

Deferred Fuel and Purchased Power Costs

     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

     The balance of APS’ pretax deferred fuel and purchased power regulatory asset (“PSA deferrals”) at March 31, 2006 was $169 million. Based on the ACC’s approval of the May 1, 2006 interim adjustor and $15 million PSA surcharge (see “Interim Rate Increase” and “Application for PSA Surcharges” in Note 5), APS estimates that its pretax PSA deferral balance at December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim rate relief and based on APS’ hedged positions for fuel and purchased power at March 31, 2006; recent forward market prices for natural gas and purchased power (which are subject to change); strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.

     The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages. APS has requested the recovery of these deferrals through a PSA surcharge upon the ACC’s completion of an inquiry regarding the outages.

     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. APS began a planned outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage, determined to perform the necessary work and modifications to remedy the situation prior to returning the Unit to service. APS believes that performing the work during the current Unit 1 outage will provide greater assurance that Unit 1 will be operating during the peak summer months and somewhat accelerate returning the Unit to full power (which is currently expected in the June timeframe).

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APS estimates that pretax incremental replacement power costs resulting from Unit 1’s current outage and reduced power levels were approximately $36 million during the three months ended March 31, 2006 and that such costs will be approximately $47 million in the second quarter of 2006. The related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and are estimated to be approximately $42 million in the second quarter of 2006. The Palo Verde replacement power costs were partially offset by $17 million of lower replacement power costs related to strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006. As a result, the corresponding deferrals were reduced in the quarter by $15 million. As noted under “Interim Rate Increase” under Note 5, the ACC has directed the ACC staff to undertake a prudence audit of all unplanned 2006 Palo Verde outage costs.

     See Note 5 for further information regarding the PSA and APS’ pending PSA surcharge application.

Operating Results – Three-month period ended March 31, 2006 compared with three-month period ended March 31, 2005

     Our consolidated net income for the three months ended March 31, 2006 was $12 million compared with $24 million for the comparable prior-year period. The three months ended March 31, 2005 included an after-tax net loss from discontinued operations of $6 million, which was related primarily to the operations of Silverhawk, partially offset by sales of commercial properties at SunCor. Income from continuing operations decreased $18 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment – Income from continuing operations decreased approximately $26 million primarily due to higher fuel and purchased power costs (as discussed above) and higher prices, and higher operations and maintenance expense related to generation and customer service costs. These negative factors were partially offset by deferred fuel and purchased power costs; higher retail sales volumes due to customer growth; a retail price increase effective April 1, 2005; and higher interest income.

• Real Estate Segment – Income from continuing operations increased approximately $13 million primarily due to increased parcel and home sales.

• Marketing and Trading Segment – Income from continuing operations decreased approximately $5 million primarily due to lower mark-to-market gains on contracts for future delivery and the absence of Off-System Sales that we began reporting in the regulated electricity segment in April 2005.

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Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Higher fuel and purchased power costs	$	(55	)	$	(34	)
Deferred fuel and purchased power costs (fuel deferrals began April 1, 2005)		13			8
Higher retail sales volumes due to customer growth, excluding weather effects		13			8
Retail price increase effective April 1, 2005		7			4
Effects of weather on retail sales		(3	)		(2	)
Miscellaneous items, net		(4	)		(2	)
Net decrease in regulated electricity segment gross margin		(29	)		(18	)
Marketing and trading segment gross margin:
Lower mark-to-market gains on contracts for future delivery due to changes in forward prices		(9	)		(6	)
Lower realized margins on wholesale sales primarily due to the absence of sales that we began reporting in the regulated segment in April 2005		(5	)		(3	)
Miscellaneous items, net		6			4
Net decrease in marketing and trading segment gross margin		(8	)		(5	)
Net decrease in gross margin for regulated electricity and marketing and trading segments		(37	)		(23	)
Higher real estate segment contribution primarily related to increased parcel and home sales		22			13
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(18	)		(11	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(5	)		(3	)
Depreciation and amortization decreases primarily due to lower depreciation rates, partially offset by increased depreciable assets		3			2
Higher other income, net of expense primarily due to increased interest income		5			3
Miscellaneous items, net		—			1
Net decrease in income from continuing operations	$	(30	)		(18	)
Discontinued operations related to:
Silverhawk operations in 2005					7
Sales of real estate assets					(1	)
Net decrease in net income				$	(12	)

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     Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $50 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:

• a $19 million increase in retail revenues related to customer growth, excluding weather effects;

• an $18 million increase in revenues related to the implementation of the February 1, 2006 PSA adjustor, which has no earnings effect due to the offset from amortization of deferred fuel in fuel and purchased power expense;

• a $12 million increase in Off-System Sales primarily resulting from sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

• a $7 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $4 million decrease in retail revenues related to weather; and

• a $2 million decrease due to miscellaneous factors.

     Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $4 million lower for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:

• a $22 million increase from higher volumes of competitive retail sales in California;

• a $12 million decrease in Off-System Sales due to the absence of sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

• a $9 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices; and

• a $5 million decrease due to miscellaneous factors.

     Real Estate Revenues

     Real estate revenues were $38 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily due to increased parcel and home sales at SunCor.

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LIQUIDITY AND CAPITAL RESOURCES

Capital Needs and Resources – Pinnacle West Consolidated

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the three months ended March 31, 2006 and estimated capital expenditures for the next three years:

CAPITAL EXPENDITURES
(dollars in millions)

	Three Months Ended		Estimated for the Year Ended
	March 31,		December 31,
	2006		2006		2007		2008
APS
Distribution	$	86	$	322	$	323	$	362
Transmission		25		120		169		203
Generation		31		184		207		279
Other (a)		6		23		16		13
Subtotal		148		649		715		857
SunCor (b)		46		232		142		119
Other		1		6		2		6
Total	$	195	$	887	$	859	$	982

(a)	Primarily information systems and facilities projects.
(b)	Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.

     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $35 million annually for 2006 through 2008.

     Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005 outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit

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3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS’ share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through 2005 with the remaining $55 million included in future years in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.

Contractual Obligations

     Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:

• fuel and purchased power commitments, which increased from approximately $1.9 billion at December 31, 2005 to $3 billion at March 31, 2006 as follows (in billions):

2006	2007-2008	2009-2010	Thereafter	Total
$0.4	$0.5	$0.4	$1.7	$3.0

     See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.

     Off-Balance Sheet Arrangements

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2006, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.

     Guarantees and Letters of Credit

     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of May 8, 2006 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue

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for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).

	Moody’s	Standard & Poor’s
Pinnacle West
Senior unsecured1	(P) Baa3	BB+ (prelim)
Commercial paper	P-3	A-3
Outlook	Negative	Stable
APS
Senior unsecured	Baa2	BBB-
Secured lease obligation bonds	Baa2	BBB-
Commercial paper	P-2	A-3
Outlook	Negative	Stable

¹ Pinnacle West has a shelf registration under SEC rule 415. Moody’s assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim) rating to such shelf registrations. Pinnacle West currently has no outstanding, rated senior unsecured securities.

     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For each of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At March 31, 2006, the ratio was approximately 50% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage is approximately 3.6 times under APS’ bank financing agreements as of March 31, 2006. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.

     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

     All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under

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these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.

     See Note 4 for further discussions.

Capital Needs and Resources — By Company

     Pinnacle West (Parent Company)

     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2006, APS’ common equity ratio, as defined, was approximately 54%.

     Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, common and collective trusts and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $14 million of which was contributed on April 14, 2006. The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

     In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).

     On March 22, 2006, the Pinnacle West Board of Directors declared a quarterly dividend of $0.50 per share of common stock, payable on June 1, 2006, to shareholders of record on May 1, 2006.

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     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April, 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.

     APS

     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

     See “Cash Flow Hedges” in Note 10 for information related to collateral provided to us by counterparties.

     Pinnacle West Energy

     See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of the sale of our 75% ownership interest in Silverhawk.

     Other Subsidiaries

     During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during the three months ended March 31, 2006 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

     El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.

     APS Energy Services expects minimal capital expenditures over the next three years.

CRITICAL ACCOUNTING POLICIES

     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting

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period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting, the determination of the appropriate accounting for our pension and other postretirement benefits and derivatives accounting. There have been no changes to our critical accounting policies since our 2005 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2005 Form 10-K for further details about our critical accounting policies.

PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.

     Retail Rate ProceedingsThe key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, APS has pending before the ACC a general retail rate case and an application for a surcharge under the PSA.

     Fuel and Purchased Power CostsFuel and purchased power costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service, variances in deferrals and amortization of fuel and purchased power beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. See “Natural Gas Supply” in Note 12 for more information on fuel costs. See “Deferred Fuel and Purchased Power Costs” for information about Palo Verde Unit 1’s current outage to remedy an operating condition, the unit’s previous reduced power levels resulting from that condition, and the associated economic impact. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

     Customer and Sales GrowthThe customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of weather variations. Customer growth for the three-month period ended March 31, 2006 compared with the prior-year period was 4.5%.

     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our

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kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.

     WeatherIn forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

     Wholesale Power Market ConditionsThe marketing and trading division focuses primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.

Other Factors Affecting Financial Results

     Operations and Maintenance ExpensesOperations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, acquisition, the sale of generation (see discussion of the sale of Silverhawk – Note 17), changes in depreciation and amortization rates (see Note 5), and changes in regulatory asset amortization.

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant in 2005 and our additions to transmission and distribution facilities are included in the property tax base.

     Interest ExpenseInterest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

     Retail CompetitionAlthough some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

     SubsidiariesSunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million in 2005. See Note 17 for further discussion.

     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

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     GeneralOur financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

Market Risks

     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.

     Interest Rate and Equity Risk

     We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of debt securities held by our nuclear decommissioning trust fund. The nuclear decommissioning trust fund also has risk associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

     Commodity Price Risk

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

	•	Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and
��	•	Marketing and Trading – non-trading and trading derivative instruments of our competitive business segment.

     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the three months ended March 31, 2006 and 2005 (dollars in millions):

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	Three Months Ended						Three Months Ended
	March 31, 2006						March 31, 2005
	Regulated			Marketing			Regulated			Marketing
	Electricity			and Trading			Electricity			and Trading
Mark-to-market of net positions at beginning of period	$	335		$	181		$	33		$	107
Recognized in earnings:
Change in mark-to-market for future period deliveries – gains (losses)		(5	)		—			13			14
Mark-to-market gains realized including ineffectiveness during the period		(4	)		(1	)		—			(8	)
Deferred as a regulatory asset		(49	)		—			—			—
Recognized in OCI:
Change in mark-to-market for future period deliveries – gains (losses) (a)		(163	)		(42	)		108			52
Mark-to-market gains realized during the period		(10	)		(7	)		(1	)		(5	)
Mark-to-market of net positions at end of period	$	104		$	131		$	153		$	160

(a) The increases (decreases) in regulated mark-to-market recorded in OCI are due primarily to increases (decreases) in forward natural gas prices.

     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at March 31, 2006 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2005 Form 10-K for more discussion of our valuation methods.

Regulated Electricity

																			Total
																Years			fair
Source of Fair Value	2006			2007			2008			2009			2010			thereafter			value
Prices actively quoted	$	19		$	83		$	32		$	2		$	—		$	—		$	136
Prices provided by other external sources		—			6			—			(1	)		—			—			5
Prices based on models and other valuation methods		(3	)		(3	)		(4	)		(1	)		(3	)		(23	)		(37	)
Total by maturity	$	16		$	86		$	28		$	—		$	(3	)	$	(23	)	$	104

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Marketing and Trading

															Total
															fair
Source of Fair Value	2006			2007			2008		2009			2010			value
Prices actively quoted	$	52		$	—		$	—	$	—		$	—		$	52
Prices provided by other external sources		—			70			19		—			—			89
Prices based on models and other valuation methods		(21	)		(3	)		16		(1	)		(1	)		(10	)
Total by maturity	$	31		$	67		$	35	$	(1	)	$	(1	)	$	131

     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005 (dollars in millions).

	March 31, 2006						December 31, 2005
	Gain (Loss)						Gain (Loss)
	Price Up			Price Down			Price Up		Price Down
Commodity	10%			10%			10%		10%
Mark-to-market changes reported in earnings (a):
Electricity	$	(1	)	$	1		$	—	$	—
Natural gas		—			—			—		—
Other		—			—			—		—
Mark-to-market changes reported in OCI (b):
Electricity		54			(54	)		66		(66	)
Natural gas		90			(90	)		103		(103	)
Total	$	143		$	(143	)	$	169	$	(169	)

(a)	These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
(b)	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

     We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 10% of Pinnacle West’s $887 million of risk management and trading assets as of March 31, 2006. See Note 1, “Derivative

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Accounting” in Item 8 of our 2005 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.2 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.

Deferred Fuel and Purchased Power Costs

     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

     The balance of APS’ pretax deferred fuel and purchased power regulatory asset (“PSA deferrals”) at March 31, 2006 was $169 million. Based on the ACC’s approval of the May 1, 2006 interim adjustor and $15 million PSA surcharge (see “Interim Rate Increase” and “Application for PSA Surcharges” in Note 5), APS estimates that its pretax PSA deferral balance at December 31, 2006 will be approximately $160 million to $180 million assuming no additional interim rate relief and based on APS’ hedged positions for fuel and purchased power at March 31, 2006; recent forward market prices for natural gas and purchased power (which are subject to change); strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006; and the operating performance at Palo Verde Unit 1 discussed below.

     The PSA deferral balances at March 31, 2006 and estimated at December 31, 2006 each include $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages. APS has requested the recovery of these deferrals through a PSA surcharge upon the ACC’s completion of an inquiry regarding the outages.

     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. APS began a planned outage of Unit 1 on March 18, 2006 and, based on early inspections and testing during that outage, determined to perform the necessary work and modifications to remedy the situation prior to returning the Unit to service. APS believes that performing the work during the current Unit 1 outage will provide greater assurance that Unit 1 will be operating during the peak summer months

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and somewhat accelerate returning the Unit to full power (which is currently expected in the June timeframe). APS estimates that pretax incremental replacement power costs resulting from Unit 1’s current outage and reduced power levels were approximately $36 million during the three months ended March 31, 2006 and that such costs will be approximately $47 million in the second quarter of 2006. The related PSA deferrals were approximately $32 million in the three months ended March 31, 2006 and are estimated to be approximately $42 million in the second quarter of 2006. The Palo Verde replacement power costs were partially offset by $17 million of lower replacement power costs related to strong performance from APS’ fossil-fueled generating units during the three months ended March 31, 2006. As a result, the corresponding deferrals were reduced in the quarter by $15 million. As noted under “Interim Rate Increase” under Note 5, the ACC has directed the ACC staff to undertake a prudence audit of all unplanned 2006 Palo Verde outage costs.

     See Note 5 for further information regarding the PSA and APS’ pending PSA surcharge application.

Operating Results – Three-month period ended March 31, 2006 compared with three-month period ended March 31, 2005

     APS had a net loss of $6 million for the three-month period ended March 31, 2006 compared with net income of $27 million for the comparable prior-year period. The $33 million decrease was primarily due to higher fuel and purchased power costs (as discussed above) and higher prices, and higher operations and maintenance expense related to generation (including the PWEC Dedicated Assets APS acquired on July 29, 2005) and customer service costs. These negative factors were partially offset by deferred fuel and purchased power costs; higher mark-to-market gains on contracts for future delivery; higher retail sales volumes due to customer growth; and a retail price increase effective April 1, 2005.

     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Higher fuel and purchased power costs	$	(53	)	$	(32	)
Deferred fuel and purchased power costs (fuel deferrals began April 1, 2005)		13			8
Higher mark-to-market gains on contracts for future delivery due to changes in forward prices		14			9
Higher retail sales volumes due to customer growth, excluding weather effects		13			8
Retail price increase effective April 1, 2005		7			4
Effects of weather on retail sales		(3	)		(2	)
Miscellaneous items, net		(5	)		(3	)
Net decrease in gross margin		(14	)		(8	)
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(16	)		(10	)
Costs of PWEC Dedicated Assets not included in prior year period		(8	)		(5	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(5	)		(3	)
Miscellaneous items, net		(2	)		(1	)
Depreciation and amortization increases primarily due to increased depreciable assets, partially offset by lower depreciation rates		(4	)		(2	)
Higher property taxes due to increased plant in service		(4	)		(2	)
Miscellaneous items, net		—			(2	)
Net decrease in net income	$	(53	)	$	(33	)

     Regulated Electricity Revenues

     Regulated electricity revenues were $49 million higher for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:

• a $19 million increase in retail revenues related to customer growth, excluding weather effects;

• an $18 million increase in revenues related to the implementation of the February 1, 2006 PSA adjustor which has no earnings effect due to the offset from amortization of deferred fuel in fuel and purchased power expense;

• a $12 million increase in Off-System Sales primarily resulting from sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement;

• a $7 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $4 million decrease in retail revenues related to weather; and

• a $3 million decrease due to miscellaneous factors.

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     Marketing and Trading Revenues

     Marketing and trading revenues were $13 million lower for the three months ended March 31, 2006 compared with the prior-year period primarily as a result of:

• a $15 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes;

• a $14 million increase in mark-to-market gains on contracts for future delivery due to changes in forward prices; and

• a $12 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement.

ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES

     Contractual Obligations

     APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K with the exception of our aggregate:

• fuel and purchased power commitments, which increased from approximately $1.7 billion at December 31, 2005 to $2.9 billion at March 31, 2006 as follows (in billions):

2006	2007-2008	2009-2010	Thereafter	Total
$0.3	$0.5	$0.4	$1.7	$2.9

     See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.

FORWARD-LOOKING STATEMENTS

     This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2005 Form 10-K, these factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome and timing of APS’ retail rate proceedings pending before the ACC;

• the timely recovery of PSA deferrals;

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• the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;

• the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring;

• market prices for electricity and natural gas;

• power plant performance and outages;

• transmission outages and constraints;

• weather variations affecting local and regional customer energy usage;

• customer growth and energy usage;

• regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile fuel and purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

• the cost of debt and equity capital and access to capital markets;

• current credit ratings remaining in effect for any given period of time;

• our ability to compete successfully outside traditional regulated markets (including the wholesale market);

• the performance of our marketing and trading activities due to volatile market liquidity and any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

• changes in accounting principles generally accepted in the United States of America and the interpretation of those principles;

• the performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to Pinnacle West’s pension plan and APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;

• technological developments in the electric industry;

• the strength of the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and

• other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

     (a) Disclosure Controls and Procedures

     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78aet seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2006. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of March 31, 2006. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

     (b) Changes In Internal Control Over Financial Reporting

     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended March 31, 2006 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

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Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

     See Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report in regard to pending or threatened litigation or other disputes.

Item 1A. RISK FACTORS

      In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the 2005 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in the 2005 Form 10-K are not the only risks facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition and/or operating results of APS and Pinnacle West.

Item 5. OTHER INFORMATION

Construction and Financing Programs

     See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of the Company and its subsidiaries.

Regulatory Matters

     See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.

Environmental Matters

     See “Environmental Matters – Superfund” in Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.

     Navajo Nation Environmental Issues

     On May 18, 2005, APS, Salt River Project and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. See “Navajo Nation Environmental Issues” in Part I, Item 1 of the 2005 Form 10-K. On March 21, 2006, the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners. The EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of the pending litigation in the Navajo Nation Supreme Court and the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

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Item 6. EXHIBITS

     (a) Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West	Reconciliation of Operating Income to Gross Margin
99.2	APS	Reconciliation of Operating Income to Gross Margin

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     In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibita	Effective
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	11-14-88
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005	3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93
3.4	APS	Arizona Public Service Company Bylaws, amended as of June 23, 2004	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	8-9-04

^a Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION      (Registrant)
Dated: May 9, 2006	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief
		Financial Officer
		(Principal Financial Officer
		and Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY      (Registrant)
Dated: May 9, 2006	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief
		Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)

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Index to Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West	Reconciliation of Operating Income to Gross Margin
99.2	APS	Reconciliation of Operating Income to Gross Margin

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